Olefin production utilizing whole crude oil/condensate feedstock and selective hydrocracking

ABSTRACT

A method for thermally cracking a feed composed of whole crude oil and/or natural gas condensate using a vaporizer to vaporize the feed before cracking same, recovering pyrolysis gas oil from the cracked feed, subjecting the recovered pyrolysis gas oil to hydrocracking to form a paraffinic hydrocracked product, and passing at least part of the hydrocracked product to the vaporizer as additional thermal cracking feed.

BACKGROUND OF INVENTION

1. Field of Invention

This invention relates to the formation of olefins by thermal crackingof liquid whole crude oil and/or condensate derived from natural gas ina manner that is integrated with a hydrocracking operation. Moreparticularly, this invention relates to utilizing whole crude oil and/ornatural gas condensate as a feedstock for an olefin production plantthat employs hydrocarbon thermal cracking in a pyrolysis furnace incombination with a hydrocracking operation in a manner that reduces thesulfur content of the products of that plant.

2. Description of the Prior Art

Thermal (pyrolysis) cracking of hydrocarbons is a non-catalyticpetrochemical process that is widely used to produce olefins such asethylene, propylene, butenes, butadiene, and aromatics such as benzene,toluene, and xylenes.

Basically, a hydrocarbon feedstock, such as naphtha, gas oil or otherfractions of whole crude oil that are produced by distilling orotherwise fractionating whole crude oil, is mixed with steam whichserves as a diluent to keep the hydrocarbon molecules separated. Thesteam/hydrocarbon mixture is preheated to from about 900 to about 1,000degrees Fahrenheit (F), and then enters the reaction zone where it isvery quickly heated to a severe hydrocarbon thermal cracking temperaturein the range of from about 1,450 to about 1,550 F. Thermal cracking isaccomplished without the aid of any catalyst.

This process is carried out in a pyrolysis furnace (steam cracker) atpressures in the reaction zone ranging from about 10 to about 30 psig.Pyrolysis furnaces have internally thereof a convection section and aradiant section. Preheating is accomplished in the convection section,while severe cracking occurs in the radiant section.

After severe thermal cracking, the effluent from the pyrolysis furnacecontains gaseous hydrocarbons of great variety, e.g., from one tothirty-five carbon atoms per molecule. These gaseous hydrocarbons can besaturated, monounsaturated, and polyunsaturated, and can be aliphatic,alicyclics, and/or aromatic. The cracked gas also contains significantamounts of molecular hydrogen (hydrogen).

Thus, conventional steam (thermal) cracking, as carried out in acommercial olefin production plant, employs a fraction of whole crudeand totally vaporizes that fraction while thermally cracking same.

The cracked product is then further processed in the olefin productionplant to produce, as products of the plant, various separate individualstreams of high purity such as hydrogen, ethylene, propylene, mixedhydrocarbons having four carbon atoms per molecule, fuel oil, andpyrolysis gasoline. Each separate individual stream aforesaid is avaluable commercial product in its own right. Thus, an olefin productionplant currently takes a part (fraction) of a whole crude stream andgenerates therefrom a plurality of separate, valuable products.

Natural gas and whole crude oil(s) were formed naturally in a number ofsubterranean geologic formations (formations) of widely varyingporosities. Many of these formations were capped by impervious layers ofrock. Natural gas and whole crude oil (crude oil) also accumulated invarious stratigraphic traps below the earth's surface. Vast amounts ofboth natural gas and/or crude oil were thus collected to formhydrocarbon bearing formations at varying depths below the earth'ssurface. Much of this natural gas was in close physical contact withcrude oil, and, therefore, absorbed a number of lighter molecules fromthe crude oil.

When a well bore is drilled into the earth and pierces one or more ofsuch hydrocarbon bearing formations, natural gas and/or crude oil can berecovered through that well bore to the earth's surface.

The terms “whole crude oil” and “crude oil” as used herein means liquid(at normally prevailing conditions of temperature and pressure at theearth's surface) crude oil as it issues from a wellhead separate fromany natural gas that may be present, and excepting any treatment suchcrude oil may receive to render it acceptable for transport to a crudeoil refinery and/or conventional distillation in such a refinery. Thistreatment would include such steps as desalting. Thus, it is crude oilthat is suitable for distillation or other fractionation in a refinery,but which has not undergone any such distillation or fractionation. Itcould include, but does not necessarily always include, non-boilingentities such as asphaltenes or tar. As such, it is difficult if notimpossible to provide a boiling range for whole crude oil. Accordingly,whole crude oil could be one or more crude oils straight from an oilfield pipeline and/or conventional crude oil storage facility, asavailability dictates, without any prior fractionation thereof.

Natural gas, like crude oil, can vary widely in its composition asproduced to the earth's surface, but generally contains a significantamount, most often a major amount, i.e., greater than about 50 weightpercent (wt. %), methane. Natural gas often also carries minor amounts(less than about 50 wt. %), often less than about 20 wt. %, of one ormore of ethane, propane, butane, nitrogen, carbon dioxide, hydrogensulfide, and the like. Many, but not all, natural gas streams asproduced from the earth can contain minor amounts (less than about 50wt. %), often less than about 20 wt. %, of hydrocarbons having from 5 to12, inclusive, carbon atoms per molecule (C5 to C12) that are notnormally gaseous at generally prevailing ambient atmospheric conditionsof temperature and pressure at the earth's surface, and that cancondense out of the natural gas once it is produced to the earth'ssurface. All wt. % are based on the total weight of the natural gasstream in question.

When various natural gas streams are produced to the earth's surface, ahydrocarbon composition often naturally condenses out of the thusproduced natural gas stream under the then prevailing conditions oftemperature and pressure at the earth's surface where that stream iscollected. There is thus produced a normally liquid hydrocarbonaceouscondensate separate from the normally gaseous natural gas under the sameprevailing conditions. The normally gaseous natural gas can containmethane, ethane, propane, and butane. The normally liquid hydrocarbonfraction that condenses from the produced natural gas stream isgenerally referred to as “condensate,” and generally contains moleculesheavier than butane (C5 to about C20 or slightly higher). Afterseparation from the produced natural gas, this liquid condensatefraction is processed separately from the remaining gaseous fractionthat is normally referred to as natural gas.

Thus, condensate recovered from a natural gas stream as first producedto the earth's surface is not the exact same material, composition wise,as natural gas (primarily methane). Neither is it the same material,composition wise, as crude oil. Condensate occupies a niche betweennormally gaseous natural gas and normally liquid whole crude oil.Condensate contains hydrocarbons heavier than normally gaseous naturalgas, and a range of hydrocarbons that are at the lightest end of wholecrude oil.

Condensate, unlike crude oil, can be characterized by way of its boilingpoint range. Condensates normally boil in the range of from about 100 toabout 650F. With this boiling range, condensates contain a wide varietyof hydrocarbonaceous materials. These materials can include compoundsthat make up fractions that are commonly referred to as naphtha,kerosene, diesel fuel(s), and gas oil (fuel oil, furnace oil, heatingoil, and the like). Naphtha and associated lighter boiling materials(naphtha) are in the C5 to C10, inclusive, range, and are the lightestboiling range fractions in condensate, boiling in the range of fromabout 100 to about 400 F. Petroleum middle distillates (kerosene,diesel, atmospheric gas oil) are generally in the C10 to about C20 orslightly higher range, and generally boil, in their majority, in therange of from about 350 to about 650 F. They are, individually andcollectively, referred to herein as “distillate” or “distillates.” Itshould be noted that various distillate compositions can have a boilingpoint lower than 350 F and/or higher than 650 F, and such distillatesare included in the 350-650 F range aforesaid, and in this invention.

The starting feedstock for a conventional olefin production plant, asdescribed above, has first been subjected to substantial, expensiveprocessing before it reaches that plant. Normally, condensate and wholecrude oil is distilled or otherwise fractionated in a crude oil refineryinto a plurality of fractions such as gasoline, naphtha, kerosene, gasoil (vacuum or atmospheric) and the like, including, in the case ofcrude oil and not natural gas, a high boiling residuum. Thereafter anyof these fractions, other than the residuum, are normally passed to anolefin production plant as the starting feedstock for that plant.

It would be desirable to be able to forego the capital and operatingcost of a refinery distillation unit (whole crude processing unit) thatprocesses condensate and/or crude oil to generate a hydrocarbonaceousfraction that serves as the starting feedstock for conventional olefinproducing plants. However, the prior art, until recently, taught awayfrom even hydrocarbon cuts (fractions) that have too broad a boilingrange distribution. For example, see U.S. Pat. No. 5,817,226 to Lenglet.

Recently, U.S. Pat. No. 6,743,961 (hereafter “USP '961”) issued toDonald H. Powers. This patent relates to cracking whole crude oil byemploying a vaporization/mild cracking zone that contains packing. Thiszone is operated in a manner such that the liquid phase of the wholecrude that has not already been vaporized is held in that zone untilcracking/vaporization of the more tenacious hydrocarbon liquidcomponents is maximized. This allows only a minimum of solid residueformation which residue remains behind as a deposit on the packing. Thisresidue is later burned off the packing by conventional steam airdecoking, ideally during the normal furnace decoking cycle, see column7, lines 50-58 of that patent. Thus, the second zone 9 of that patentserves as a trap for components, including hydrocarbonaceous materials,of the crude oil feed that cannot be cracked or vaporized under theconditions employed in the process, see column 8, lines 60-64 of thatpatent.

Still more recently, U.S. Pat. No. 7,019,187 issued to Donald H. Powers.This patent is directed to the process disclosed in USP '961, butemploys a mildly acidic cracking catalyst to drive the overall functionof the vaporization/mild cracking unit more toward the mild cracking endof the vaporization (without prior mild cracking)-mild cracking(followed by vaporization) spectrum.

The disclosures of the foregoing patents, in their entirety, areincorporated herein by reference.

One skilled in the art would first subject the feed to be cracked to aconventional distillation column to distill the distillate from thecracking feed. This approach would require a substantial amount ofcapital to build the column and outfit it with the normal reboiler andoverhead condensation equipment that goes with such a column. In thisinvention, a splitter is employed in a manner such that much greaterenergy efficiency at lower capital cost is realized over a distillationcolumn. By use of this splitter, reboilers, overhead condensers, andrelated distillation column equipment are eliminated without eliminatingthe functions thereof, thus saving considerably in capital costs.Further, this invention exhibits much greater energy efficiency inoperation than a distillation column because the extra energy that wouldbe required by a distillation column is not required by this inventionsince this invention instead utilizes for its splitting function theenergy that is already going to be expended in the operation of thecracking furnace (as opposed to energy expended to operate a standalonedistillation column upstream of the cracking furnace), and the vaporproduct of the splitter goes directly to the cracking section of thefurnace.

Finally, this invention integrates the foregoing splitter process withconventional hydrocracking.

SUMMARY OF THE INVENTION

In accordance with this invention, there is provided a process forutilizing whole crude oil and/or natural gas condensate as the feedstockfor an olefin plant, as defined above, in combination with a selectivehydrocracking process in a manner which increases the productivity ofthe cracking process and at the same time reduces the sulfur content ofvarious products recovered from that olefin plant.

DESCRIPTION OF THE DRAWING

FIG. 1 shows a simplified flow sheet for a process within thisinvention.

DETAILED DESCRIPTION OF THE INVENTION

The terms “hydrocarbon,” “hydrocarbons,” and “hydrocarbonaceous” as usedherein do not mean materials strictly or only containing hydrogen atomsand carbon atoms. Such terms include materials that arehydrocarbonaceous in nature in that they primarily or essentially arecomposed of hydrogen and carbon atoms, but can contain other elementssuch as oxygen, sulfur, nitrogen, metals, inorganic salts, and the like,even in significant amounts.

An olefin producing plant useful with this invention would include apyrolysis (thermal cracking) furnace for initially receiving andcracking the feed. Pyrolysis furnaces for steam cracking of hydrocarbonsheat by means of convection and radiation, and comprise a series ofpreheating, circulation, and cracking tubes, usually bundles of suchtubes, for preheating, transporting, and cracking the hydrocarbon feed.The high cracking heat is supplied by burners disposed in the radiantsection (sometimes called “radiation section”) of the furnace. The wastegas from these burners is circulated through the convection section ofthe furnace to provide the heat necessary for preheating the incominghydrocarbon feed. The convection and radiant sections of the furnace arejoined at the “cross-over,” and the tubes referred to hereinabove carrythe hydrocarbon feed from the interior of one section to the interior ofthe next.

Cracking furnaces are designed for rapid heating in the radiant sectionstarting at the radiant tube (coil) inlet where reaction velocityconstants are low because of low temperature. Most of the heattransferred simply raises the hydrocarbons from the inlet temperature tothe reaction temperature. In the middle of the coil, the rate oftemperature rise is lower but the cracking rates are appreciable.

At the coil outlet, the rate of temperature rise increases somewhat butnot as rapidly as at the inlet.

Steam dilution of the feed hydrocarbon lowers the hydrocarbon partialpressure, enhances olefin formation, and reduces any tendency towardcoke formation in the radiant tubes.

Radiant coils in the furnace heat the hydrocarbons to from about 1,450°F. to about 1,550° F. and thereby subject the hydrocarbons to severecracking.

Hydrocarbon feed to the furnace is preheated to from about 900° F. toabout 1,000° F. in the convection section by convectional heating fromthe flue gas from the radiant section, steam dilution of the feed in theconvection section, or the like. After preheating in a conventionalcommercial furnace, the feed is ready for entry into the radiantsection.

The cracked gaseous hydrocarbons leaving the radiant section are rapidlyreduced in temperature to prevent destruction of the cracking pattern.Cooling of the cracked gases before further processing of samedownstream in the olefin production plant recovers a large amount ofenergy as high pressure steam for re-use in the furnace and/or olefinplant. This is often accomplished with the use of transfer-lineexchangers that are well known in the art.

Downstream processing of the cracked hydrocarbons issuing from thefurnace varies considerably, and particularly based on whether theinitial hydrocarbon feed was a gas or a liquid. Since this inventionuses whole crude oil and/or liquid natural gas condensate as a feed,downstream processing herein will be described for a liquid fed olefinplant. Downstream processing of cracked gaseous hydrocarbons from liquidfeedstock, naphtha through gas oil for the prior art, and crude oiland/or condensate for this invention, is more complex than for gaseousfeedstock because of the heavier hydrocarbon components present in theliquid feedstocks.

With a liquid hydrocarbon feedstock downstream processing, although itcan vary from plant to plant, typically employs termination of thecracking function by a transfer-line exchanger followed by oil and waterquenches of the furnace effluent. Thereafter, the cracked hydrocarbonstream is subjected to fractionation to remove heavy liquids, followedby compression of uncondensed hydrocarbons, and acid gas and waterremoval therefrom. Various desired products are then individuallyseparated, e.g., ethylene, propylene, a mixture of hydrocarbons havingfour carbon atoms per molecule, fuel oil, pyrolysis gasoline, and a highpurity hydrogen stream.

In accordance with this invention, a process is provided which utilizescrude oil and/or condensate liquid that has not been subjected tofractionation, distillation, and the like, as the primary (initial)feedstock for the olefin plant pyrolysis furnace in whole or insubstantial part. By so doing, this invention eliminates the need forcostly distillation of the condensate into various fractions, e.g., fromnaphtha, kerosene, gas oil, and the like, to serve as the primaryfeedstock for a furnace as is done by the prior art as first describedhereinabove.

This invention can be carried out using, for example, the apparatusdisclosed in USP '961. Thus, this invention is carried out using aself-contained vaporization facility that operates separately from andindependently of the convection and radiant sections of the furnace.When employed outside the furnace, crude oil and/or condensate primaryfeed is preheated in the convection section of the furnace, passed outof the convection section and the furnace to a standalone vaporizationfacility. The vaporous hydrocarbon product of this standalone facilityis then passed back into the furnace to enter the radiant sectionthereof. Preheating can be carried out other than in the convectionsection of the furnace if desired or in any combination inside and/oroutside the furnace and still be within the scope of this invention.

The vaporization unit of this invention (for example section 3 of USP'961) receives the condensate feed that may or may not have beenpreheated, for example, from about ambient to about 350F, preferablyfrom about 200 to about 350F. This is a lower temperature range thanwhat is required for complete vaporization of the feed. Any preheatingpreferably, though not necessarily, takes place in the convectionsection of the same furnace for which such condensate is the primaryfeed.

Thus, the first zone in the vaporization operation step of thisinvention (zone 4 in USP '961) employs vapor/liquid separation whereinvaporous hydrocarbons and other gases, if any, in the preheated feedstream are separated from those distillate components that remain liquidafter preheating. The aforesaid gases are removed from the vapor/liquidseparation section and passed on to the radiant section of the furnace.

Vapor/liquid separation in this first, e.g., upper, zone knocks outdistillate liquid in any conventional manner, numerous ways and means ofwhich are well known and obvious in the art.

Liquid thus separated from the aforesaid vapors moves into a second,e.g., lower, zone (zone 9 in USP '961). This can be accomplished byexternal piping. Alternatively this can be accomplished internally ofthe vaporization unit. The liquid entering and traveling along thelength of this second zone meets oncoming, e.g., rising, steam. Thisliquid, absent the removed gases, receives the full impact of theoncoming steam's thermal energy and diluting effect.

This second zone can carry at least one liquid distribution device suchas a perforated plate(s), trough distributor, dual flow tray(s), chimneytray(s), spray nozzle(s), and the like.

This second zone can also carry in a portion thereof one or moreconventional tower packing materials and/or trays for promoting intimatemixing of liquid and vapor in the second zone.

As the remaining liquid hydrocarbon travels (falls) through this secondzone, lighter materials such as gasoline or naphtha that may be presentcan be vaporized in substantial part by the high energy steam with whichit comes into contact. This enables the hydrocarbon components that aremore difficult to vaporize to continue to fall and be subjected tohigher and higher steam to liquid hydrocarbon ratios and temperatures toenable them to be vaporized by both the energy of the steam and thedecreased liquid hydrocarbon partial pressure with increased steampartial pressure.

FIG. 1 shows one embodiment of the process of this invention indiagrammatic form for sake of simplicity and brevity.

FIG. 1 shows a conventional cracking furnace 1 wherein a crude oiland/or condensate primary feed 2 is passed in to the preheat section 3of the convection section of furnace 1. Steam 6 is also superheated inthis section of the furnace for use in the process of this invention.

The pre-heated cracking feed is then passed by way of pipe (line) 10 tothe aforesaid vaporization unit 11, which unit is separated into anupper vaporization zone 12 and a lower zone 13. This unit 11 achievesprimarily (predominately) vaporization with or without mild cracking ofat least a significant portion of the naphtha and gasoline boiling rangeand lighter materials that remain in the liquid state after thepre-heating step. Gaseous materials that are associated with thepreheated feed as received by unit 11, and additional gaseous materialsformed in zone 12, are removed from zone 12 by way of line 14. Thus,line 14 carries away essentially all the lighter hydrocarbon vapors,e.g., naphtha and gasoline boiling range and lighter, that are presentin zone 12. Liquid distillate present in zone 12, with or without someliquid gasoline and/or naphtha, is removed therefrom via line 15 andpassed into the upper interior of lower zone 13. Zones 12 and 13, inthis embodiment, are separated from fluid communication with one anotherby an impermeable wall 16, which can be a solid tray. Line 15 representsexternal fluid down flow communication between zones 12 and 13. In lieuthereof, or in addition thereto, zones 12 and 13 can have internal fluidcommunication there between by modifying wall 16 to be at least in partliquid permeable by use of one or more trays designed to allow liquid topass down into the interior of zone 13 and vapor up into the interior ofzone 12. For example, instead of an impermeable wall 16, a chimney traycould be used in which case vapor carried by line 17 would passinternally within unit 11 down into section 13 instead of externally ofunit 11 via line 15. In this internal down flow case, distributor 18becomes optional.

By whatever way liquid is removed from zone 12 to zone 13, that liquidmoves downwardly into zone 13, and thus can encounter at least oneliquid distribution device 18. Device 18 evenly distributes liquidacross the transverse cross section of unit 11 so that the liquid willflow uniformly across the width of the tower into contact with packing19.

Dilution steam 6 passes through superheat zone 20, and then, via line 21into a lower portion 22 of zone 13 below packing 19. In packing 19liquid and steam from line 21 intimately mix with one another thusvaporizing some of liquid 15. This newly formed vapor, along withdilution steam 21, is removed from zone 13 via line 17 and added to thevapor in line 14 to form a combined hydrocarbon vapor product in line25. Stream 25 can contain essentially hydrocarbon vapor from feed 2,e.g., gasoline and naphtha, and steam.

Stream 17 thus represents a part of feed stream 2 plus dilution steam 21less liquid distillate(s) and heavier from feed 2 that are present inbottoms stream 44. Stream 25 is passed through a mixed feed preheat zone27 in a hotter (lower) section of the convection zone of furnace 1 tofurther increase the temperature of all materials present, and then viacross over line 28 into the radiant coils (tubes) 29 in the radiantfirebox of furnace 1. Line 28 can be internal or external of furnacecross over conduit 30. Line 44 removes from stripper 11 the residuum, ifany, from feed 2.

Steam 6 can be employed entirely in zone 13, or a part thereof can beemployed in either line 14 and/or line 25 to aid in the prevention ofthe formation of liquid in lines 14 or 25.

In the radiant firebox section of furnace 1, feed from line 28 whichcontains numerous varying hydrocarbon components is subjected to severethermal cracking conditions as aforesaid.

The cracked product leaves the radiant fire box section of furnace 1 byway of line 31 for further processing in the remainder of the olefinplant downstream of furnace 1 as shown in USP '961.

In a conventional olefin production plant, the preheated feed 10 wouldbe mixed with dilution steam 21, and this mixture would then be passeddirectly from preheat zone 3 into the radiant section 29 of furnace 1,and subjected to severe thermal cracking conditions. In contrast, thisinvention instead passes the preheated feed at, for example, atemperature of from about 200 to about 350F, into standalone unit 11which is physically located outside of furnace 1.

In the embodiment of FIG. 1, cracked furnace product 31 is passed to atleast one transfer line exchanger 32 (TLE in FIG. 1) wherein it iscooled sufficiently to terminate the thermal cracking function. Thecracked gas product is removed by way of line 33 and further cooled byinjection of recycled quench oil 34 immediately downstream of TLE 32.The quench oil/cracked gas mixture passes via line 33 to oil quenchtower 35. In tower 35 this mixture is contacted with a hydrocarbonaceousliquid quench material such as pyrolysis gasoline which boils in therange of from about 100 to about 420F. Pyrolysis gasoline is providedfrom line 36 to further cool the cracked gas furnace product as well ascondense and recover additional fuel oil product for line 34. Crackedgas product is removed from tower 35 via line 37 and passed to waterquench tower 38 wherein it is contacted with recycled and cooled water39 that is recovered from a lower portion of tower 38. Water 39condenses liquid pyrolysis gasoline in tower 38 which is, in part,employed as liquid quench material 36, and, in part, removed via line 40for other processing elsewhere.

The thus processed cracked gas product is removed from tower 38 via line41 and passed to compression and fractionation facility 42 whereinindividual product streams aforesaid are recovered as products of thecracking plant, such individual product streams being collectivelyrepresented by way of line 43.

In tower 35 there is present a hydrocarbonaceous fraction known aspyrolysis gas oil. Pyrolysis gas oil boils in a temperature range offrom about 380 to about 700F. Normally pyrolysis gas oil is separatedfrom the process and used or sold as fuel oil. However, with thisinvention pyrolysis gas oil is used to provide additional feed for thecracking process. Since the process of this invention uses whole crudeoil and/or natural gas condensate as its primary feed material,significantly more quantities of pyrolysis gas oil are produced, andthis invention takes advantage of this result.

Pursuant to this invention, a side draw stream 50 is taken from tower 35which stream is essentially pyrolysis gas oil. Stream 50 is then fed toa conventional selective hydrocracking operation 51, and thehydrocracked product, at least in part, recycled via line 52 to stream 2to provide more feed to be subjected to thermal cracking, therebyimproving the overall product yield per unit of feed 2 of the thermalcracking process represented in FIG. 1. In addition, the hydrocrackedproduct in line 52 has, by virtue of the hydrocracking process, beensubstantially reduced in sulfur content thereby reducing the overallsulfur content of the various products 40 and 43 of the plant. Thehydrocracked product in line 52 can, in part, be removed from theprocess and sent to a refinery as feed to one or more of a distillationtower, a conversion process such as a fluid catalytic cracker orreformer, distillation blending operations, gasoline blendingoperations, kerosene blending operations, diesel blending operations,and the like.

Optionally, pursuant to this invention, a side draw stream 53 can betaken from stripper 11 and passed to hydrocracking operation 51 therebyadditionally enhancing the overall productivity and sulfur reductionadvantages of this invention for the steam cracking process. Stream 53can be gaseous, liquid or a combination thereof. Stream 53 can besubjected to a distillation step, if desired, to remove material that isundesirable in a hydrocracking process.

Feed 2 can enter furnace 1 at a temperature of from about ambient up toabout 300 F at a pressure from slightly above atmospheric up to about100 psig (hereafter “atmospheric to 100 psig”). Feed 2 can enter zone 12via line 10 at a temperature of from about ambient to about 500 F at apressure of from atmospheric to 100 psig.

Stream 14 can be essentially all hydrocarbon vapor formed from feed 2and is at a temperature of from about 500 to about 750 F at a pressureof from atmospheric to 100 psig.

Stream 15 can be essentially all the remaining liquid from feed 2 lessthat which was vaporized in pre-heater 3 and is at a temperature of fromabout 500 to about 750 F at a pressure of from atmospheric to 100 psig.

The combination of streams 14 and 17, as represented by stream 25, canbe at a temperature of from about 650 to about 800 F at a pressure offrom atmospheric to 100 psig, and contain, for example, an overallsteam/hydrocarbon ratio of from about 0.1 to about 2.

Stream 28 can be at a temperature of from about 900 to about 1,100 F ata pressure of from atmospheric to 100 psig.

In zone 13, dilution ratios (hot gas/liquid droplets) will vary widelybecause the composition of condensate varies widely. Generally, the hotgas 21, e.g., steam, to hydrocarbon ratio at the top of zone 13 can befrom about 0.1/1 to about 5/1, preferably from about 0.1/1 to about1.2/1, more preferably from about 0.1/1 to about 1/1.

Steam is an example of a suitable hot gas introduced by way of line 21.Other materials can be present in the steam employed. Stream 6 can bethat type of steam normally used in a conventional cracking plant. Suchgases are preferably at a temperature sufficient to volatilize asubstantial fraction of the liquid hydrocarbon 15 that enters zone 13.Generally, the gas entering zone 13 from conduit 21 will be at leastabout 350 F, preferably from about 650 to about 1,000 F at fromatmospheric to 100 psig.

Stream 17 can be a mixture of steam and hydrocarbon vapor that has aboiling point lower than about 350 F. It should be noted that there maybe situations where the operator desires to allow some distillate toenter stream 17, and such situations are within the scope of thisinvention. Stream 17 can be at a temperature of from about 600 to about800 F at a pressure of from atmospheric to 100 psig.

It can be seen that steam from line 21 does not serve just as a diluentfor partial pressure purposes as does diluent steam that may beintroduced, for example, into conduit 2 (not shown). Rather, steam fromline 21 provides not only a diluting function, but also additionalvaporizing energy for the hydrocarbons that remain in the liquid state.This is accomplished with just sufficient energy to achieve vaporizationof heavier hydrocarbon components and by controlling the energy input.For example, by using steam in line 21, substantial vaporization of feed2 liquid is achieved. The very high steam dilution ratio and the highesttemperature steam are thereby provided where they are needed most asliquid hydrocarbon droplets move progressively lower in zone 13.

The term “selective hydrocracking” (hydrocracking) refers to a processof treating a feed with hydrogen for a period of time and at atemperature sufficient to render a product wherein less than or equal to5 wt. % of the product has a boiling point less than 380 F. It typicallyconsists of four operations. First, metals such as vanadium and nickelare removed from the feed using separate or mixed catalyst beds. Second,sulfur, oxygen, and/or nitrogen are removed from or minimized in thefeed. Third, polynuclear aromatic compounds are saturated to naphthenicor cycloparaffinic rings. Fourth, the saturated naphthenic orcycloparaffinic rings are opened to straight chain or branched chainparaffinic hydrocarbons without reduction of the number of carbon atomsin the reacted hydrocarbon molecules.

Preferably, metals removal and hydrodesulfurization/hydrodenitrificationare carried out in separate beds in series with recycled hydrogencontaining progressively higher concentrations of hydrogen sulfide andammonia, and the aromatics saturation process is carried out in a secondstage with hydrogen containing minimal hydrogen sulfide.

In general hydrocracking consists of first removing from the feed metalsand heterocyclic atoms, such as nitrogen, oxygen and sulfur prior to theentry of the feed into the aromatic saturation section. The process nextincludes the saturation of polynuclear aromatics in the feed. Duringtreatment in the aromatic saturation section, breaking of thecarbon-carbon bonds of the aromatic compounds is not intended. It is notnecessary for monoaromatic compounds to be entirely saturated. Once thearomatic rings are saturated further treatment will selectivelyhydrocrack and open the naphthenic or cycloparaffinic rings to straightchain or branched paraffinic hydrocarbons. It is preferred to operatethe treatment so that less than 5 wt. % of the treated product convertedfrom the feed has a boiling point range of less than about 380 F.

Preferably, metals removal and hydrodesulfurization/hydronitrificationare carried out in separate beds; and the saturation process is carriedout in a third stage with hydrogen containing minimal hydrogen sulfidein counter current or concurrent flow. Hydrocracking is carried out in afourth bed with hydrogen containing minimal hydrogen sulfide in countercurrent or concurrent flow.

It is desirable to minimize the amount of cracking that occurs in thefeed during treatment that produces hydrocarbon compounds that have alower molecular weight than the starting material. While a limitedamount of hydrodealkylation may be both unavoidable and tolerated,severe cracking of the product requires unnecessarily greater quantitiesof hydrogen and forms products which may have a poorer overall olefinyield profile. The third step serves to saturate the polynucleararomatics.

Useful catalyst compositions are well known in the art, and commerciallyavailable. Metal oxide catalysts are cobalt-molybdenum, nickel-tungsten,and nickel-molybdenum supported catalysts, usually on alumina.

Ring opening requires a catalyst bed with low acid functionality such asamorphous silica alumina or a crystalline molecular sieve or a zeoliteand can carry a Group VIII noble metal.

The same catalysts can be used for demetallization,desulfurization/denitrification, and saturation. Any catalyst which iscapable of removing most metals and substantially all sulfur andnitrogen content from the feed can be used. In addition, the catalystselected should be capable of catalyzing the hydrogenation of compoundscontaining aromatic rings without substantial structural alteration orbreakdown. Suitable catalysts include cobalt/molybdenum/alumina,nickel/cobalt/molybdenum/alumina, cobalt/molybdenum/alumina,nickel/molybdenum/alumina, and cobalt/tungsten/alumina. Such catalystscan also be used in their sulfided form.

The catalysts are prepared by impregnating a catalyst support with anaqueous solution of a salt of the metal, either consecutively orsimultaneously. Nickel can be added in the form of nickel nitrate,tungsten as ammonium metatungstate, cobalt as cobalt nitrate, acetate,etc., and molybdenum and ammonium molybdate. It is convenient toimpregnate the support first with the salt of the metal that is to bepresent in the highest concentration in the finished catalyst. Othermethods include precipitating the metals on the support from a solutionof their salts and co-precipitation of the metals with the hydratedsupport.

For maximum effectiveness, the metal oxide catalysts used for saturationshould be converted at least in part to metal sulfides. The metal oxidecan be sulfided by contact at elevated temperatures with hydrogensulfide or a sulfur-containing oil. Alternatively, a commerciallyavailable metal oxide having sulfur incorporated therein can be used.These presulfurized catalysts can be loaded into the treatment unit andbrought up to reaction conditions in the presence of hydrogen causingthe sulfur to react with the hydrogen. The metal oxides are therebyconverted to sulfides.

Preferably, the saturation catalysts are activated before use in thereaction by contact with a stream of hydrogen containing hydrogensulfide at a temperature in the range of from about 212 to about 1,472 Ffor from about 1 minute to about 24 hours. The sulfided form of thecatalyst can be prepared by passing hydrogen through liquidtetrahydrothiophene and then over the catalyst maintained at atemperature in the range of from about 212 to about 1,472 F for fromabout 1 minute to about 24 hours.

The hydrocracking catalyst containing Group VIII noble metals must bereduced with a stream of hydrogen at a temperature in the range of fromabout 212 to about 1,472 F for from about 1 minute to about 24 hours.

Hydrocracking is conducted at high temperatures and high pressures.Typically, the temperature in the hydrogenation chamber is in the rangeof from about 640 to about 840 F, and a pressure in the range of fromabout 1,200 to about 5,000 psig. The hydrocarbon Weight Hourly SpaceVelocity can be in the range of from about 0.1 to about 5.0. Hydrogensupply can be in the range of from about 100 to about 2,000 cubic metersper ton of the hydrocarbon feed.

Hydrogen can be passed through scrubbers to remove hydrogen sulfide andammonia before recycle. Hydrogenation can be carried out in a series oftwo or more operations using the same or different catalysts thoughsingle stage hydrogenation may be acceptable. Hydrogen flow can be inthe co-current or counter current direction.

EXAMPLE

A natural gas condensate stream 5 characterized as Oso condensate fromNigeria is removed from a storage tank and fed directly into theconvection section of a pyrolysis furnace 1 at ambient conditions oftemperature and pressure. In this convection section, this condensateinitial feed is preheated to about 350 F at about 60 psig, and thenpassed into a vaporization unit 11 wherein a mixture of gasoline andnaphtha gases at about 350 F and 60 psig are separated from distillateliquids in zone 12 of that unit. The separated gases are removed fromzone 12 for transfer to the radiant section of the same furnace forsevere cracking in a temperature range of 1,450° F. to 1,550° F. at theoutlet of radiant coil 29.

The hydrocarbon liquid remaining from feed 2, after separation fromaccompanying hydrocarbon gases aforesaid, is transferred to lowersection 13 and allowed to fall downwardly in that section toward thebottom thereof. Preheated steam 21 at about 1,000 F is introduced nearthe bottom of zone 13 to give a steam to hydrocarbon ratio in section 22of about 0.5. The falling liquid droplets are in counter current flowwith the steam that is rising from the bottom of zone 13 toward the topthereof. With respect to the liquid falling downwardly in zone 13, thesteam to liquid hydrocarbon ratio increases from the top to bottom ofsection 19.

A mixture of steam and naphtha vapor 17 at about 340 F is withdrawn fromnear the top of zone 13 and mixed with the gases earlier removed fromzone 12 via line 14 to form a composite steam/hydrocarbon vapor stream25 containing about 0.5 pounds of steam per pound of hydrocarbonpresent. This composite stream is preheated in zone 27 to about 1,000 Fat less than about 50 psig, and introduced into the radiant fireboxsection of furnace 1.

Bottoms product 44 of unit 11 is removed at a temperature of about 460F, and pressure of about 60 psig.

Oil quench tower 35 is operated at a bottom temperature of about 450 Fat about 10 psig. Side draw stream 50 is withdrawn and passed tohydrocracking unit 51 which contains nickel/molybdenum catalyst followedby a molecular sieve with platinum catalyst and is maintained at atemperature of about 650 F and pressure of about 2,900 psig. The productof unit 51 is returned via line 52 to cracking feed line 2.

1. In a method for operating an olefin production plant that employs apyrolysis furnace to severely thermally crack hydrocarbon containingmaterial for subsequent processing of the thus cracked product in saidplant which method of plant operation includes 1) providing at least oneof whole crude oil and natural gas condensate as said hydrocarboncontaining material, 2) submitting said whole crude/condensate feed to avaporization step wherein said feed is substantially vaporized, and 3)feeding said substantially vaporized feed to said pyrolysis furnace,said plant further employing an oil quench step on said cracked materialproduct to form a pyrolysis gas oil stream, the improvement comprisingpassing at least part of said pyrolysis gas oil stream to ahydrocracking step, hydrocracking said pyrolysis gas oil to form ahydrocracked product, and returning at least part of said hydrocrackedproduct as feed to said vaporization step.
 2. The method of claim 1wherein a liquid stream is removed from said vaporization step andpassed as feed to said hydrocracking step.
 3. The method of claim 1wherein said pyrolysis gas oil stream boils in the range of from about380 to about 700 F.
 4. The method of claim 1 wherein said hydrocrackingstep is carried out at a temperature of from about 640 to about 840 F,pressure of from about 1,200 to about 5,000 psig, weight hourly spacevelocity of from about 0.1 to about 5, and hydrogen flow of from about100 to about 200 cubic meters per ton of hydrocarbon feed.